Energy efficient power generation in Tirora, India
Host party(ies) India
Methodology(ies) ACM0013 ver. 2
Standardised Baselines N/A
Estimated annual reductions* 1,193,768
Start date of first crediting period. 01 May 11
Length of first crediting period. 10 years
Period for comments 01 Jan 09 - 30 Jan 09
The operational/applicant entity working on this project has decided to make the Project Design Document (PDD) publicly available directly on the UNFCCC CDM website.
PDD PDD (937 KB)
Local stakeholder consultation report: N/A
Impact assessment summary: N/A
Submission of comments to the DOE/AE Compilation of submitted inputs:
1.	Another project from Adani Group – The first observation, change of DOE since the previous DOE (DNV) was made aware about the shortcomings in the PDD which in turn must have been informed to the PP and thus this shift? Well, the PP can always say that at the time of finalization of this PDD, DNV was under suspension and thus could not take up new validation assignments. Dear SGS team; I along with my observations on the present PDD would also provide you with my previous observations on the Adani project (grid connected energy efficient power generation); webhosted last year. The comments are annexed to this submission.
2.	SGS – You have been carrying out validations and verifications for past so many year and I am sure you have been following the best practices; could you please check the titles of the ACM 0013 PDDs submitted from India? And confirm that the titles of the PDD are unique enough to identify the projects?
3.	 SGS – Please have a look at the PDD submitted by the same PDD about 6 months back (trust you would be able to locate it on the UNFCCC website) and just compare the financial analysis carried out by PP
a.	This PDD - the capital cost is INR 49 million / MW – Super Critical
b.	The previous PDD, the capital cost was INR 43 million / MW – Super Citical
Please note that the unit size in both the cases is same (660 MW) and both the projects are still to be implemented, I am sure you would understand the logic – economy of scale and thus the PP can surly procure the plant & machinery from the same EPC contractor i.e. 660 MW * 4 units to reduce the inventory burden and better price bargain position (am I right?)
If that is the case how come the price has changed within 6 months?
And now please see the flip side of it; in the previous PDD the sub critical option was available to the same PP at INR 33 million / MW and now within 6 months in this PDD, the sub critical option is available to the PP at 26 million / MW
The super critical technology has gone costlier and the sub critical technology has gone cheaper in 6 months. When was this PP lying? In the earlier case, or in this case?
Please note that both the documents are now available in public domain and the PP cannot back out on submissions.
I would request the UNFCCC / RIT to take a note of such submissions.
SGS – are you still willing to move ahead, well then there is no need to even do a Google search, just go through other two super critical PDDs of Reliance and Tata power wherein the capital cost for super critical is presented. And if you do not have the time, then I am there to extend the necessary assistance; the capital investment showcased there is about INR 42.5 million / MW, then how come Adani is so very costly? Is there something cooking to make the project additional?
SGS – Still not happy with my submission, in such a scenario, may I request you to please check the CEA website – thermal power monitoring (CEA – Central Electricity Authority) and you will see capital investment for super critical at INR 40 million / MW
Now would you please help the global stakeholders with detailed assumptions and supporting documents relevant to the project?
4.	Investment guidance states that Investment analysis should be done considering standard parameters, since the data available on supercritical states that the capital cost is much lower (please check Tata and Sasan PDDs and comments) the investment analysis should be carried out considering these capital cost. Since Adani’s project is in inception stage, this capital cost can not be relied on as Adani can fabricate the numbers to show additionality.
5.	No reason why Grid imports can’t be considered as part of baseline scenario, grid import as baseline alternative can not ruled out since now all the grids are interconnected. The project is coming up in 2014, Government of India is undertaking several projects to upgrade the transmission capacity. So by 2014, it can not be assumed that the same constraints would prevail. Therefore further analysis of Grid imports as a baseline alternative must be included.
6.	Project will use Imported coal (that’s why its location is selected as Tiara), the cost of imported cost would be significantly higher as compared to Indian coal, in such a case, it is the obvious economical choice to put up a supercritical project because the higher efficiency leads to higher savings. If imported coal prices are considered, the levelised cost of generation of a super critical plant would be significantly lower as compared to a sub critical plant. An investment analysis of both the alternatives would clearly show that Super critical (imported coal) has lower levelised cost as compared to sub critical (imported coal), making super critical as baseline.
7.	Fuel price considered is very low, since Maharastra does not have a coal mine the landed cost of coal would be in excess of Rs. 1500/ton (please check MahaGenco’s tariff orders, you will easily find this number). Plus the GCV of coal also has been projected to be high, the GCV of coal that Maharastra plants get is around 3500, if the levelised cost is worked out at this GCV and fuel cost, supercritical at any day would work out to be cheaper than subcritical.
There are various reports available on the internet Check this report on the net - [I am providing one link for your convenience] please see page 69 which provides the average landed cost of coal as INR 1443 / ton, average coal GCV is 3662 (page 62).
Interesting thing is that these are prices of 2005-06 whereas they the project completion time would be somewhere between 2013-14 (although they have mentioned the crediting period as 2011-12, it can not happen since the bids for EPC were invited in October 2008, the bidder is yet to be selected and plant gestation period would atleast 4 years from zero date). In the PDD they have assumed a coal price inflation of 5% which by 2014 would make the coal price as Rs.1750. At such high coal prices, supercritical would be obviously the more economical choice
Project developer must submit the excel sheet calculations for public review, the DOE can not know what goes into a power plant workings, and hence these workings must be shared. Plus the parameters provided in the PDD are clearly not sufficient to workout the levelised cost, there are a number of other parameters like, specific fuel consumption, phasing of cap-ex etc that needs to be provided for the public to analyse the levelised cost workings. 
8.	ACM 0013 clearly states that the baseline and additionality analysis need not be carried out thinking all the capacity would come from a single plant, ACM 0013 states that it can be assumed that the capacity can come from several smaller projects. Therefore the investment analysis of sub-critical should be carried out considering the entire 1320 MW and not 1000 MW. 
9.	Project is connected to NEWNE, in the same grid, Sasan power plant is there that has a levelised cost of Rs. 1.19 per units, this is the lowest tariff any thermal plant has offered in India and therefore this plant has proven that supercritical is by far the most economical technology. Even if it is argued that CDM benefits are considered for Sasan, the levelised cost without CDM would workout to about Rs.1.25 per unit which again is lowest among all power plants. So it is clearly not the technology that is expensive. Adani is fabricating details to make the project look additional. 
10.	Auxiliary consumption is taken as the same, whereas auxiliary consumption for supercritical would be around 5% and not 7.5% as depicted
11.	The relevant parameters for investment in power plants is the equity IRR or the RoE. Levelisd cost can not be the parameter since the tariff is borne by the consumer and not the project developer. The incentive to the project developer is the equity IRR and hence equity IRR and not levelised cost should be financial parameter. DOE may note that if levelised cost were to be considered all wind projects in India, by default would become additional, since the levelised cost of wind would any day be highest among all power plants. DOE would note that the CDM EB insists on looking at the IRR and benchmark for demonstrating additionality. It is really a surprise how someone can invest INR 65000 million without considering IRR 
12.	Another interesting point is that the levelised cost has been worked out considering 14% ROE which means that in supercritical scenario also the project developer was anyway getting 14% ROE. This rate of return has been prevalent for 20 years in India and most of India’s 120,000 MW capacity have been implemented at this rate of return. If the developer is anyway getting 14% ROE (since levelised costs include this ROE) there is no reason why the project developer should get CDM.
13.	Common practice – page 21 of the PDD 
You have written that currently there are no projects in India that use super critical technology. Your project also is not going to be operational before 2012. The common practice test therefore should consider capacity addition programs. In the 11th plan (2007 – 12), Government of India has targeted 88,000 MW thermal capacity addition. The capacity addition from super critical in the 11th plan is as follows:
	Capacity MW
9 UMPPs (9 x 4000 MW)	36,000
NTPC Sipat	1,980
NTPC Barh	1,980
Adani Power	1,320
IFFCO Chhatisgarh	1,320
Coastal Power Projects using imported/blended coal	10,000
Total	54,200
Out of 88,000 MW capacity planned, 54200 MW or 62% is expected to come from Supercritical projects. Still you have written that common practice analysis for the project is not necessary. I would request SGS to look into this in more detail. 
14.	Start date is February 2008, so CDM delay needs to be justified, the DOE surprisingly has not insisted on the same. 
15.	As can be seen the PDD is clearly incomplete, therefore the DOE must re-webhost the PDD so that the global stakeholder consultation can be carried out properly. The CDM EB has to note how these DOEs collude with the PPs to carefully avoid this requirement.
Annexure – Comments on the previous project of same PP

I remember the last time I had pointed out severe loopholes in the Tata Power Supercritical PDD, and Mr. Michael Lehmen of DNV personally wrote to me assuring that DNV will adhere to professional ethics while carrying out the validation of the PDD. Well! it seems after all, the professional ethics of DNV only lies in paper, for it has gone ahead and made the same blunders in this PDD as well. I don’t know whether the CDM EB and the RIT are noticing this or not….but for the time being this is surely a reassertion of the growing perception that the CDM is but a money spinning machine….I have decided that I am going to send all my comments so far to a news paper and ask them to publish this so that at least the general public becomes aware of how the system has been corrupted. 
Now let me just point out some of observations of a non CDM person like myself that experts like DNV could not identify….my question to the CDM EB, don’t you guys think that such omissions appear more to be a matter of convenience rather than inadvertent errors?? 
1.	Section B.4. Description of Baseline Scenario
•	Under ACM0013, the baseline alternatives need not consist solely of power plants of the same capacity, load factor and operational characteristics (i.e. several smaller plants, or the share of a larger plant may be a reasonable alternative to the project activity), however they should deliver similar services (e.g. peak vs. base load power). Note further that the baseline scenario candidates identified may not be available to project participants, but could be other stakeholders within the grid boundary (e.g. other companies investing in power capacity expansions).

What this means that the baseline scenarios should not only include the alternatives available to the project proponent but also should also include alternatives that are available to other power companies as well. Reliance Power is implementing a 4000 MW super critical project at Sasan, Madhya Pradesh. Therefore the baseline alternative analysis should also include Reliance’s Sasan UMPP as one of the plausible alternatives. The levelised cost of generation of Sasan UMPP is Rs. 1.19 [, I have also given the web link in case your intelligent minds are unable to find it]. I am comparing the levelised costs given in page 16 of PDD and that of Sasan UMPP.

	Alternative 1: Project without CDM	Alternative 2:  Sub-critical coal plant	Alternative 3: Sasan UMPP
Levelised Cost	2.20	2.05	1.19

Clearly, Sasan UMPP has the lowest cost among all alternatives and hence should be the baseline. Even if one assumes that Sasan could also go for CDM, the price would still be around Rs. 1.25 per unit (assuming 5 to 6 paise CDM benefits per unit). Even after CDM benefits are factored out, Sasan super critical is still the cheapest source of power in the country. 

The other important consideration here is that Sasan is a pit head plant, where the coal cost is lowest and hence the benefit of a super critical technology (higher fuel efficiency) would be minimum in such a case. However despite of this Sasan is by far the cheapest source of electricity in India. 

•	The calorific value of coal for sub-critical and super critical project is assumed to be 6000 kcal/kg and 6000 kcal/kg. How can the technology make a difference to the quality of coal that is sourced from Indonesia. 
•	The projects emission calculation gives specific coal consumption of 0.5189 Ton/Mwh (or 0.5189 kg/Kwh). Assuming data given in the PDD (Step 2 of section B.4) is correct, calorific value of 5200 Kcal/kg and station heat rate of 2032.78 Kcal/kg, specific fuel consumption of coal will be 0.41 kg/kwh (after applying NCV/GCV ratio of 95%). Even if we assume that calorific value of coal is 6000 kcal/kg (as given in PDD for sub-critical). How can the specific fuel consumption for super-critical can be .5189 kg/kwh. 
•	Some Basics on calculation of project emissions: The proportion of carbon in coal given in the PDD is 47.64 %. Considering this data as correct the calorific value of coal shall be 6000 kcal/kg (12600 X 0.4764). Now if I compare this value with the assumptions in step 2 of section B.4 of PDD (5200 Kcal/kg), they refuse to match. This one adds to confusion as which value is correct.
•	For further analysis, I am considering calorific value of coal as 6,000 Kcal/Kwh. The efficiency for the project can be calculated from station heat rate. The efficiency for the super-critical and sub-critical is calculated based on the values given in the PDD. Referring to methodology, efficiency of the technology that has been identified as the baseline scenario shall be used to estimate baseline emissions. Sub-critical technology with station heat rate of 2131.43 kcal/kg is chosen as an baseline alternative (as given in the PDD assumptions). This implies that efficiency of the sub-critical technology is pegged at 40.45%. I am very sure that project proponent has deliberately used different set of values in additionality argument and for setting baseline. If we replace the assumptions used under additionality analysis with efficiency of 30.07% which is used in baseline calculations, the levelised cost of generation for the sub-critical will definitely just the levelised cost for super-critical. The project proponents have very intelligently camouflaged the efficiency of the sub-critical power project at two locations in the PDD. 

Baseline			PDD Values
S.No.	Description	Units	Sub-Critical	Super-Critical
1	Station heat Rate	Kcal/Kwh	2131.43	2032.78
2	GCV	Kcal/kg	6000	6000
3	NCV*	Kcal/kg	5700	5700
4	Efficiency	 	40.45%	42.41%
5	% of carbon in coal	 	47.62%	47.62%

Ton of coal	Kcal (Calorific value of Coal)	GJ	TCO2	EF
         5,100,000 	      30,600,000,000,000 	                  128,214,000 	            8,908,680 	0.069483

2.	Section B.5. Additionality
I was going through the draft Validation and Verification manual published by the CDM EB and I found that there is a clause called “Transparency”. Para 30 of the VVM describes that Transparency is to disclose information to allow intended users to understand and to make decisions with reasonable confidence. The VVM also states that Transparency requires documenting assumptions, references and methods such that another party can reproduce reported data;
Let us for a moment assume that the esteemed professionals at DNV did not bother to verify this. But then again, I find that the additionality tool clearly states the following:
“Present the investment analysis in a transparent manner and provide all the relevant assumptions, preferably in the CDM-PDD, or in separate annexes to the CDM-PDD, so that a reader can reproduce the analysis and obtain the same results. 
•	Now my question is, do you or the PP feel that the assumptions provided in the PDD are sufficient to recreate the financial model of a 1320 MW Greenfield power project. Are you guys out of your mind??? Do you have any idea how many parameters go into the financial model of a power plant of this size and how a minor variation in one of the parameters can significantly alter the outcome of the financial analysis. Understood that you may not have in-depth experience in power sector financial modeling, however there are some outlandish errors that anyone just fairly acquainted with the power sector could have identified easily.
•	Efficiency: Levelised costs have been calculated assuming a 42.31% super critical efficiency and a 40.36% sub critical efficiency. A simple google search generates a hundred documents that would say that the efficiency of super critical projects is typically 5 to 7% higher than a sub critical project. I am sure Adani Power would have given you some piece of paper to prove the efficiency numbers, but I urge DNV should to use some professional skepticism to review these documents, as I hope you would understand that this would have a telling impact on the outcome of the financial analysis.
•	Auxiliary consumption: I hope you understand that a 9% number for auxiliary consumption in case of a sub critical plant and a 7.5% number in case of a super critical plant are extremely high. The new sub critical units have auxiliary consumption of about 5% and the super critical units about 4%. Its actually strange that you guys need to be told about this.
•	Capital cost of sub critical plant: The capital cost of green field sub critical coal fired plant would range anywhere between Rs. 40 million to Rs. 42 million per MW. Strangely, the capital cost assumed for the sub critical unit is about Rs.33 million per MW, which is about 25% lower that what it should be. Let me tell you DNV, you don’t have to be a rocket scientist to figure out the impact it will have on levelised cost calculations.
•	Capital cost of super critical plant. Costs for a super-critical and sub-critical power plant can be broken into comparable cost components. The main module of a super critical plant that contributes to its high cost (in comparison to a sub critical plant) is the BTG package. I am presenting the cost break up of a typical super critical unit and that of a sub critical unit and hope that you will try to use it for cross checking information provided by Adani Power	Cost Heads	Super-Critical	Sub-Critical	Equipments covered under each head
1	Civil Structure	13,866	13,866	 
2	Major Mechanical Equipment	20,432	12,000	BTG(Boiler Turbine Generator), Air Pre-heater, ESP Etc.
3	BOP Mechanical Equipment	4,128	4,128	Offsites (DM Plant, CHP, AHP etc.)
4	Major Electrical Equipment	922	922	Transformmer, Switchyard etc.
5	BOP Electrical Equipment	3,109	3,109	Instrumentation and Contorl, Cable, Earthing etc
6	Chemical	458	458	Water treatment etc
7	Field Labour 	5,992	5,992	 
8	Engineering	3,142	3,142	 
9	Startup/Testing	784	784	 
10	Construction	913	913	 
11	Equipmement cost freight	2,838	2,838	 
12	Start-up Spares	231	231	 
13	Opearting Spares	668	668	 
14	Rolling Stock coal wagins and Locos	477	477	 
 	Total	57,960	49,528	 
In case of the Super-critical power plants, the BTG components are in range of 33% to 37% of the total capital investment where as for sub-critical BTG component is range of 23 to 28% of the capital cost. If we do the cost comparison of the super-critical and sub-critical, the cost differential of the completely built unit for the particular project shall be in range of 12% to 18%. Whereas it has been assumed that the cost of the super critical project is about 33% higher than that of the sub critical unit. This, no doubt, is completely erroneous.
•	Coal price escalation: You have assumed a coal price escalation of 10% for every five year block, this translates to about 1.9% coal price escalation per year. My request to DNV is to check the coal price data in the international market for the last 5 years, also I think there would international coal indexes available which can be used to ascertain the escalation rates in international coal price. I am sure no matter what the coal price volatility is, it would translate into an escalation rate that is significantly higher than what has been considered by the PP for carrying out the levelised cost. In fact CERC publishes escalation rates for coal considering the movements in two international coal indexes; you would notice that this rate is in excess of 6%. 
By considering a lower escalation rate, the PP has very cleverly tried to play down the benefits from the super critical project. Let me explain to you how: the primary benefit from a super critical project is in the form of coal savings (because of higher efficiency), therefore a higher fuel cost would mean that a super critical project would be more beneficial as compared to sub critical thermal project.
Its unfortunate that we have spend our time and effort to educate you about such basic things.
•	Heat rate assumption: What I find strange that while calculating the baseline emissions you have considered a heat rate of 2867 kcal/kWh (i.e. 30% efficiency) for the sub critical plant whereas for levelised cost calculations you have considered a heat rate of 2,131 kcal/kWh (<40% efficiency). I can’t help but think that such blatant errors are intentional misrepresentation of data to mislead the stakeholders. Isn’t DNV supposed to carry out a review of the PDD before web hosting it.
•	Coal GCV and Loan tenure assumptions: Do you guys not understand the very basics of financial analysis, when comparing two alternatives, except for the plant specific technical parameters you are supposed to keep all other parameters as constant. Now you have done is that you have happily assumed different coal GCVs and loan tenures for both the options, if you do that how in this world can you make the statement that the difference in levelised cost is on account of the super critical plant and not because of variations in these other parameters. Please think, you appear to have lost your ability to rationalize.
•	Accuracy of levelised cost calculations: I would like to give some advice here; Power plant financial models are complex, any modeling expert can manipulate these models in a manner that you won’t even have a clue to where things are wrong. You should try and get the model validated by some renowned power sector expert or a modeling expert and I am sure you will unearth many errors and grey areas in the levelised cost calculations. 
•	Additionality1: I am referring to the explanation given in the additionality tool for investment comparison analysis, I presume that you would not be using the benchmark analysis, because if you do your project will obviously be non additional. The additionality tool states that
“Identify the financial indicator, such as IRR, NPV, cost benefit ratio, or unit cost of service (e.g., levelized cost of electricity production in $/kWh or levelized cost of delivered heat in $/GJ) most suitable for the project type and decision-making context.”
I hope you understand the meaning of the words “most suitable to the project type and decision making context”, I want Adani power to tell me that the investment for a project of Rs. 54 billion was taken without calculating the IRR. Do you think people sitting in the EB are fools…..
It is very obvious that the relevant indicator for investment decision making in this case would be the IRR and only IRR. No other financial indicator can be considered as relevant here; especially when the project has additional sources of revenue other than CDM. I sincerely pledge DNV and RIT to obtain the IRR calculations that were submitted by Adani to the banks and financial institutions for obtaining loans for the project.
Here again, DNV needs to be cautious, Adani power could collude with the banks and create forged documents that show a low IRR, in which case you ought to make it public, send the bank letter to RBI and the banking obudsmen and ask the bank to clarify how it can finance a sub par project. 
•	Now lets discuss the complication that you would face if you do an IRR analysis, here I would like to draw the attention of the RIT team and the CDM EB also. The PDD clearly mentions that the levelised costs have been calculated considering an equity IRR of 14%, there is nothing wrong with this approach as a 14% benchmark number is very commonly accepted in Indian power sector. The main issue here is that even after providing for an 14% equity IRR, the levelised cost of your so called supercritical project works out to Rs.2.20/kWh. In comparison, the average HT tariff in Gujarat is close to Rs.5/kWh and the peak power tariff is in excess of Rs.10/kWh. 
I don’t know if DNV knows this, but I will still state it for your benefit. There is an essential difference between the power projects developed for supply of electricity to Distribution licensee and power project being developed as Power SEZ. In India, if a power plant is to sell electricity to the industries on the basis of bilateral contract, they have to pay a cross-subsidy surcharge that is Rs. 1 per unit and open access charges. This cross subsidy surcharge and open access charges compel most power projects to sell power to distribution licensees and go through long term PPA route. In case of Adani power, as the project is developed to supply power to SEZ areas, the cross subsidy surcharge is not applicable. This will essentially mean that the project proponent will have a command on fixing tariff that is comparable to HT tariff.  You would have noticed that the average HT tariff and the peak tariff in Gujarat is about 2 to 4 times that of the levelised cost of generation of the project. What this means that, the equity IRR of this project should also be significantly higher than 14%. 
So in essence, you will be earning an IRR that is significantly higher than the average return generated by other thermal projects in India, but you are saying that you still need CDM. I would request the RIT team to look into this…
This brings us to the larger issue of perverse incentives, the question here is if this coal fired project gets CDM benefit (i) even though its IRR is way higher than the IRR generated by other project and (ii) India has close 80,000 MW of thermal power plant all of which have been set up on the basis of a 14% IRR, does it not incentivize project developers. 
I refer to the guidance provided in the EB 39 regarding the Investment Analysis, the use of investment analysis to demonstrate additionality is intended to assess whether or not a reasonable investor would or not decide to proceed with a particular project activity without the benefits of the CDM. 
Therefore, I don’t understand how CDM can be justified for this project, when all other power sector investments in India that have been implemented so far, have taken place on the basis of significantly lower IRR. Any other project developer would have implemented a coal fired thermal power plant on the basis of a 14% IRR.
•	Additionality other considerations: 
a.	I hope that you know that Adani Power is developing power SEZ in Mundra and will therefore enjoy rebate on taxes and duties. Strangely, I find that PDD is conveniently silent about these benefits that are provided to the project. I am also not sure that these benefits have been factored in while making the levelised cost calculations. Given that neither DNV nor the PP nor the CDM EB feels it is necessary to be transparent and share the financial workings worksheet, there is no way to know if the calculations have been made correctly.
b.	HT tariff for commercial and manufacturing units is very high in the state of Gujarat, it can be safely assumed that the power that Adani will be selling to industries located in SEZ areas shall be much greater than the tariff that other power plants get in the same region. Also, the excess power that remains after serving the SEZ areas can be sold on bilateral contracts outside the SEZ region. Considering the state of Gujarat, that is power deficit, it is very evident that Adani power will be able to secure the bilateral contract with the industries or traders on long term basis at a much higher rate than the other power plants that are operation in the region. 
c.	Also, the project proponent has not bothered to indicate in the PDD the benefits that the project will enjoy under the mega power policy. Any project that is more than 1000 MW is eligible for benefits like customs duty exemption etc under mega power policy. But unfortunately both DOE and the PP do not feel it necessary to be transparent in sharing such details during the stakeholder consultation process.
•	Additionality – Common Practice: You have written that currently there are no projects in India that use super critical technology. It is common knowledge that efforts were made to bring in highly efficient super critical technology in the country for thermal power plants and execution of six super critical units of 660MW capacity each (NTPC Sipat and Barh) was taken up during the 10th Plan period. The first unit of 660 MW based on super critical technology is likely to be commissioned during the first year of 11th Plan i.e. 2007-08. Your project also is not going to be operational before 2012. The common practice test therefore should consider capacity addition programs. In the 11th plan (2007 – 12), Government of India has targeted 88,000 MW thermal capacity addition. The capacity addition from super critical in the 11th plan is as follows:
	Capacity MW
9 UMPPs (9 x 4000 MW)	36,000
NTPC Sipat	1,980
NTPC Barh	1,980
Adani Power	1,320
IFFCO Chhatisgarh	1,320
Coastal Power Projects using imported/blended coal	10,000
Total	54,200
Out of 88,000 MW capacity planned, 54200 MW or 62% is expected to come from Supercritical projects. Still you have written that common practice analysis for the project is not necessary. I would request DNV to look into this in more detail. 
•	Please also be aware that capacity additions are based upon expected demand for power. That will mean that we have to see the options form consumption side as to where this demand will be satisfied. In absence of project activity the power would have been supplied from any of the other super-critical technologies that are being planned in India. The project is operational in 2012 and will be able to supply electricity post 2012 only. If we analyze the capacity additions from super-critical accounts for 62% super-critical technology of the total thermal technology capacity additions. So, the Adani power projects will be displacing electricity that would have come from the other super-critical thermal power projects.

Submitted by: Naveen Sharma

The comment period is over.
* Emission reductions in metric tonnes of CO2 equivalent per annum that are based on the estimates provided by the project participants in unvalidated PDDs